Temporary field storage of gas to optimize field development

ABSTRACT

Methods are provided for managing the production of fluids from a low-permeability subsurface formation in a field. The subsurface formation may be a coalbed formation. The method involves producing formation fluids from a first zone in the subsurface formation for a period of time so as to at least partially dewater the first zone. The formation fluids are separated into a liquid stream that primarily comprises water, and a gas stream that primarily comprises methane gas. The water is sent for disposal, such as into a subsurface formation, while the gas is temporarily stored or flared. A gas processing facility is constructed for the field. In order to manage the outlay of capital for the field development, construction of the gas processing facility is spread out or delayed until the field is ready to produce enough gas to allow the gas processing facility to operate at a substantially greater capacity than would be provided at the beginning of field development.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention pertains to the field of recovery of hydrocarbongas from a coal-bearing formation or gas reservoir. More specifically,the present invention relates to the economically efficient developmentof a field having coalbed methane.

2. Discussion of Technology

Coal-bearing formations naturally produce methane gas. Historically, thepresence of methane was considered a safety issue for mining operations.A coal mine would need to be at least partially degassed before miningoperations could commence. This typically involved drilling a well intothe coal-bearing formation, and then venting the produced gas into theatmosphere.

Recently, oil and gas companies have increased the drilling of gas wellsinto coal formations for the purpose of capturing methane gas incommercially viable quantities. The gas is then processed and sold.Recovery of such methane, referred to as coalbed methane, has now becomea significant source of natural gas for the natural gas productionindustry. According to some estimates, coalbed methane (CBM) nowaccounts for about 10% of natural gas production in the United States.Significant CBM production occurs domestically in Wyoming, Colorado,Alabama, New Mexico, and other states.

Coal beds can be attractive targets for gas development because of theirability to retain large amounts of gas. While coal beds are typicallyconsidered low-permeability formations, a coal scam is nevertheless ableto store, in some cases, multiple times more gas (at standardconditions) than an equivalent volume of rock. This is because themethane compounds are able to adsorb onto the coal.

Many coal seams also contain water within the coal-bearing formation. Inorder to unlock the gas from the coal, the producer or field operatorwill typically “dewater” the formation. This involves drilling aplurality of water production wells. Production of water will causepressure in the coal-bearing formation to reduce and allow gas todesorb.

FIG. 1 presents a Cartesian coordinate graph 100 plotting fluid volumeversus time. The graph 100 demonstrates phases 110, 120, 130 of fielddevelopment for a coalbed methane field. Phase 110 is a dewateringstage; Phase 120 is a stable gas production stage; and Phase 130 is adecline stage.

The graph 100 also demonstrates production decline curves 140, 150.Decline curve 140 represents the production of water in units of volumeover time. Decline curve 150 represents the production of methane, alsoin units of volume over time.

It can be seen from FIG. 1 that during the dewatering stage (Phase 110),the coal-bearing formation produces relatively high volumes of water.However, as seen in decline curve 140, the water production rate fallsoff rapidly as the formation is dewatered. At the same time, as seen indecline curve 150, production of methane rapidly increases.

During the stable production stage (Phase 120), the coal-bearingformation produces increasingly smaller volumes of water. Decline curve140 shows that the water production rate continues to drop off as theformation is dewatered. At the same time, as seen in decline curve 150,production of methane stabilizes.

Finally, during the decline stage (Phase 130), the coal-bearingformation produces only relatively small volumes of water, which in somecases may be almost none. As seen in decline curve 140, the waterproduction rate trails off somewhat asymptotically. At the same time, asseen in decline curve 150, production of methane also slowly decreases.

The graph 100 of FIG. 1 represents a fairly typically decline curve fora coalbed methane field. Many CBM zones require dewatering of the coalprior to exhibiting substantial gas production. This is discussed morefully in V. A. Kuuskraa and C. F. Brandenberg, “Coalbed Methane Sparks aNew Energy Industry”, Oil and Gas Journal, 87(41), 49-56 (1989); L.Bassett, Guidelines to Successful Dewatering of CBM Wells, SPE Paper No.104,290, Society of Petroleum Engineers Eastern Regional Meeting,Canton, Ohio (Oct. 11-13, 2006); J. P. Seidle, A Numerical Study ofCoalbed Dewatering, SPE Paper No. 24,358, Society of Petroleum EngineersRocky Mountain Regional Meeting, Casper, Wyo. (May 18-21, 1992).

Many coalbed formations have significant amounts of mobile water withinnatural fracture networks. Such networks are sometimes referred to as“cleats.” Removing water from the cleats can take several months or evenseveral years. Thus, Phase 110 shown in FIG. 1 may represent a period oftime that is, for example, three to 36 months.

During the dewatering process of Phase 110, a low, but notinsignificant, amount of natural gas may be produced. This gas needs tobe dealt with. In some cases, flaring may be an option for dealing withthis early gas. However, flaring is becoming less environmentallyacceptable and, hence, alternatives are desirable.

In addition, when coalbed methane is produced, it may containnon-negligible amounts of acid gases, such as carbon dioxide or hydrogensulfide, and/or other noncombustible or poisonous gases. Such othergases may include, for example, nitrogen or mercaptans. Undesirable gascomponents need to be separated from the methane gas in order to meetpipeline specifications. For example, some pipeline specifications mayrequire that methane gas contain less than 2 mol. percent of CO₂, andless than 4 ppm H₂S and mercaptans.

In order to remove acid gases from a methane gas stream, a gasprocessing plant must be constructed at the surface. Various processeshave been devised to remove contaminants from a hydrocarbon gas stream.One commonly-used approach for treating raw natural gas involves the useof physical solvents. An example of a physical solvent is Selexol®.

Another approach for treating raw natural gas involves the use ofchemical solvents. Examples of chemical solvents include methyldiethanol amine (MDEA), and the Flexsorb® family of amines. Amine-basedsolvents rely on a chemical reaction with acid gas components in thehydrocarbon gas stream. Such chemical reactions are generally moreeffective than physical-based solvents, particularly at feed gaspressures below about 300 psia (2.07 MPa).

Hybrid solvents have also been used for the removal of acidiccomponents. Hybrid solvents employ a mixture of physical and chemicalsolvents. An example of a hybrid solvent is Sulfinol®.

Cryogenic gas processing techniques are also known. Cryogenic gasprocessing is a distillation process that generates a cooled overheadgas stream at moderate pressures (e.g., 350-550 pounds per square inchgauge (psig)). In addition, liquefied acid gas is generated as a“bottoms” product.

In any of these processing techniques, the removal of acid gases createsa “sweetened” hydrocarbon gas stream. The sweetened stream may be usedas an environmentally-acceptable fuel or as feedstock to a chemicals orgas-to-liquids facility. The sweetened gas stream may be chilled to formliquefied natural gas, or LNG.

The construction of a gas processing facility represents a significantcapital outlay before the development of a field. Managing theexpenditure of capital before and during the early development of a gasfield can be critical to obtaining favorable economics. A key aspect ofoptimizing capital outlay is to minimize excess capacity in processingand export facilities. However, coalbed methane and other gas fields,such as shale gas fields and tight gas fields, can have long ramp-uptimes prior to reaching a high, relatively constant production rate.

One way to match facility size to production rate is to use modularfacilities. However, this may not be an efficient approach sinceeconomies-of-scale may be lost. Leveraging economies-of-scale is oftenparticularly critical if the gas is to be converted to liquefied naturalgas and exported by ship or if the gas is to be transported by a longdistance pipeline.

In addition to processing facilities, transport and export facilitiesmay also be constructed to deal with gas produced during the dewateringstage of Phase 110. However, economic considerations typically favorexploiting economies of scale and constructing facilities suitable forthe gas output rate expected when a field is fully operational anddewatering has been completed for many wells. Thus, facilities suitablefor such gas rates will be significantly oversized during the initialdewatering stage of Phase 110. This mismatch between facility size andimmediate needs represents inefficient use of capital.

In addition, certain facilities have minimal ability to adjust theirthroughput rates while retaining desirable efficiencies. This may beparticularly true of liquefied natural gas (LNG) facilities and of gasprocessing for large export pipelines systems. Gas processing mayinclude dehydration, heavier hydrocarbon removal, and CO₂ and H₂Sremoval.

Therefore, a method is needed for developing a gas field wherein theconstruction of gas processing facilities and/or export facilities isdelayed until gas production rates have increased. Further, a needexists for a method for handling early gas production from a coalbedmethane formation before or while substantially full-capacity facilitiesare being constructed.

SUMMARY OF THE INVENTION

Methods for managing the production of fluids from a low-permeabilitysubsurface formation are provided herein. The subsurface formation maybe a coalbed zone, a shale gas zone, or a tight gas zone. The subsurfaceformation is in a field, such as a coalbed methane field or other fieldwherein natural gas is to be produced.

In one aspect, the method includes completing one or more wells in afirst zone within the subsurface formation, and then producing formationfluids from the first zone so as to at least partially dewater the firstzone. The method also includes completing one or more wells in a secondzone within the subsurface formation, and then producing formationfluids from the second zone so as to at least partially dewater thesecond zone.

The method further includes injecting gas from the formation fluids fromthe second zone into the first zone. The purpose is to temporarily storethe gas for later production. The method also includes completing one ormore wells in a fourth zone within the subsurface formation.

A gas processing facility is required for the field. Accordingly, themethod also includes substantially completing a gas processing facility.The gas processing facility is not substantially completed until (i) thegas production rate from the field is able to exceed a designated level,or (ii) at least the first and second zones of the subsurface formationhave been dewatered to a designated level. After substantiallycompleting the gas processing facility, the method includes co-producingformation fluids from the first zone, the second zone, and the fourthzone.

It is desirable to separate the produced formation fluids into liquidand gas components. The liquid primarily comprises water, while the gascomprises at least 50 percent methane. Accordingly, the method alsoincludes substantially separating water in the co-produced formationfluids from the gas in a separator. The gas is delivered to the gasprocessing facility for processing.

In one aspect, the method also includes completing one or more waterinjection wells in a subterranean storage zone. The subterranean zonemay be an aquifer, a salt cavern, a depleted hydrocarbon reservoir zone,or a coalbed zone that has been previously substantially dewatered. Themethod then includes separating water from the gas in the formationfluids from the first zone during dewatering, and injecting water fromthe formation fluids from the first zone into the subterranean storagezone. The method may also include flaring a majority of the gas from theformation fluids from the first zone during dewatering of the firstzone. As an alternative to flaring, the gas may be injected into asubsurface permeable zone for essentially permanent disposal.

In another aspect, the method further comprises completing one or morewells in a third zone within the subsurface formation, and producingformation fluids from the third zone so as to at least partially dewaterthe third zone. The method also includes shutting in the one or morewells completed in the second zone, and injecting gas from the formationfluids from the third zone into the first zone for temporary storage.This injecting step is done before the gas processing facility issubstantially completed. The method may then also include separatingwater from gas in the formation fluids from the second zone duringdewatering of the second zone, injecting water from the formation fluidsfrom the second zone into the subterranean storage zone, and alsoinjecting water from the formation fluids from the third zone into thesubterranean storage zone.

Another method for managing the production of fluids from alow-permeability subsurface formation is provided herein. The subsurfaceformation may be a coalbed zone, a shale gas zone, or a tight gas zone.The subsurface formation is in a field, such as a coalbed methane fieldor other field wherein natural gas is to be produced.

In one aspect, the method includes completing one or more wells in afirst zone within the subsurface formation, and producing formationfluids from the first zone so as to at least partially dewater the firstzone. The method also includes completing one or more injection wells ina zone in a second subsurface formation with higher permeability thanthe first zone. The zone in the second subsurface formation may be anaquifer, a salt cavern, or a depleted hydrocarbon reservoir zone.Preferably, the zone in the second subsurface formation is located insubsurface strata that is deeper than the subsurface formation that isundergoing dewatering.

The method further includes injecting gas produced from the first zoneinto the second subsurface formation. The gas from the first zone isheld in the second subsurface formation for temporary storage.

The method also includes completing one or more wells in a third zonewithin the subsurface formation, and producing formation fluids from thethird zone.

A gas processing facility is required for the field. Accordingly, themethod may also include substantially completing a gas processingfacility. The gas processing facility is not substantially completeduntil (i) the gas production rate from the field is able to exceed adesignated level, or (ii) at least two zones of the subsurface formationhave been dewatered to a designated level. After substantiallycompleting the gas processing facility, the method includes co-producingformation fluids from the first zone and the third zone.

It is desirable to separate the produced formation fluids into liquidand gas components. The liquid primarily comprises water, while the gascomprises at least 50 mole percent methane. Accordingly, the method alsoincludes substantially separating water in the co-produced formationfluids from the gas in a separator. The gas is delivered to the gasprocessing facility for processing.

In one aspect, the method also includes completing one or more wells ina second zone within the subsurface formation, producing formationfluids from the second zone so as to at least partially dewater thesecond zone, and injecting gas from the formation fluids from the secondzone into the zone in the second subsurface formation for temporarystorage before substantially completing the gas processing facility.

In another aspect, the method may include separating water from gas inthe formation fluids from the first zone during dewatering, anddelivering water from the formation fluids from the first zone to awater disposal location. After the gas processing facility is completed,gas is produced from the zone in the second subsurface formation, anddelivered to the separator along with the co-produced formation fluidsfrom the first zone and the third zone.

In yet another aspect, the method further includes:

completing one or more wells in a second zone within the subsurfaceformation;

producing formation fluids from the second zone so as to at leastpartially dewater the second zone;

injecting gas from the formation fluids from the second zone into a zonein a second subsurface formation with higher permeability than the firstzone for temporary storage.

separating water from gas in the formation fluids from the second zoneduring dewatering of the second zone;

separating water from gas in the formation fluids from the third zone;

delivering separated water from the formation fluids to the waterdisposal location; and

after the gas processing facility is completed, producing gas from thezone in the second subsurface formation and delivering the gas to theseparator along with the co-produced formation fluids from the firstzone, the second zone, the third zone, and the zone in the secondsubsurface formation.

Yet another method for managing the production of fluids is providedherein. The method is for managing the production of fluids from acoalbed formation in a field. The fluids comprise water and gas. In oneaspect, the method includes:

completing one or more wells in a first production section within thecoalbed formation;

producing formation fluids from the first production section so as to atleast partially dewater the first section;

completing one or more injection wells in a first subterranean storagezone;

completing one or more injection wells in a second subterranean storagezone;

separating the formation fluids into a liquid stream comprisedsubstantially of water, and a gas stream comprising at least 50 molepercent methane gas;

injecting the gas from the gas stream into a first subsurface formationfor temporary storage;

injecting water from the liquid stream into the second subterraneanstorage zone;

completing one or more wells in a subsequent production section withinthe coalbed formation;

substantially completing a gas processing facility for the field;

after the first section has been at least partially dewatered and afterthe gas processing facility is substantially completed, co-producingformation fluids from the first production section, the subsequentproduction section, and the first subterranean storage zone;

substantially separating water in the co-produced formation fluids fromthe gas in a separator; and

delivering the gas to the substantially completed gas processingfacility for processing.

The first subterranean storage zone may be a zone in the coalbedformation. Alternatively, the first subterranean storage zone may be anaquifer that is deeper than the coalbed formation.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certainillustrations and flow charts are appended hereto. It is to be noted,however, that the drawings illustrate only selected embodiments of theinventions and are therefore not to be considered limiting of scope, forthe inventions may admit to other equally effective embodiments andapplications.

FIG. 1 is graph showing various phases of development for a coalbedmethane field. Production rates for water and methane gas are shown onseparate decline curves.

FIGS. 2A and 2B present a single flowchart showing steps for managingthe production of fluids from a low-permeability formation, in oneembodiment.

FIGS. 3A through 3D provide illustrative cross-sectional views of afield under hydrocarbon gas development in accordance with the methodsherein, in one embodiment.

In FIG. 3A, formation fluids are being produced from a first zone in agas-producing formation. Produced water is sent for disposal, while thegas is flared.

In FIG. 3B, formation fluids are being produced from a second zone inthe gas-producing formation. Produced water is sent for disposal, whilemethane gas is injected into the first zone.

In FIG. 3C, formation fluids are being produced from a third zone in thegas-producing formation. Produced water is sent for disposal, whilemethane gas is injected into the first zone. Production wells from thesecond zone are shut in.

In FIG. 3D, formation fluids are being produced from a fourth zone inthe gas-producing formation, and all previous zones. Produced water issent for disposal, while methane gas is processed in a gas processingfacility and exported.

FIGS. 4A and 4B present a single flowchart showing steps for managingthe production of fluids from a low-permeability formation, in analternate embodiment.

FIGS. 5A through 5C provide illustrative cross-sectional views of afield under hydrocarbon gas development in accordance with the methodsherein, in an alternate embodiment.

In FIG. 5A, formation fluids are being produced from first and secondzones of a gas-producing formation. Produced water is sent for disposal,while methane gas is injected into a zone in a second subsurfaceformation for temporary storage.

In FIG. 5B, formation fluids are being produced from a plurality ofzones in a gas-producing formation. Produced water is sent for disposal,while methane gas is processed in a gas processing facility andexported.

In FIG. 5C, formation fluids are being produced from a plurality ofzones in a gas-producing formation, along with water andpreviously-injected methane gas from the zone in the second subsurfaceformation. Produced water is sent for disposal, while methane gas isprocessed in a gas processing facility and exported.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “coal” refers to any combustible rockcontaining more than about 50% by weight carbonaceous material, andformed by compaction and induration of plant matter.

As used herein, the terms “coal bed” or “coal seam” refer to any stratumor bed of coal. The terms may be used interchangeably herein.

As used herein, the term “coal bed formation” refers to a body of stratacontaining at least one coal bed, and typically one or more other strataincluding, without limitation, clay, shale, carbonaceous shale,sandstone and other inorganic rock types. While a coal bed formationgenerally contains organic matter, at any one location the thickness oforganic matter present can vary from almost none to nearly 100% of theformation thickness.

As used herein, the term “coalbed methane” (CBM), refers to a naturalgas consisting of primarily of methane, and also one or more acid gasessuch as carbon dioxide, nitrogen, or hydrogen sulfide. Coalbed methanemay also include lesser amounts of ethane, propane and other heavyhydrocarbons. Coalbed methane may be referred to by some as “coal gas.”CBM may be present in a free state, in an adsorbed state, and/or insolution with water or liquid hydrocarbons.

As used herein, the term “injectivity” means an indicator of therelative ease with which a fluid is injected into a rock formation.Factors affecting injectivity into a coal bed formation includepermeability, fracture conductivity, and secondary porosity. Injectivityis measured in m³/day-kPa or Mscf/day-psi.

As used herein, the term “gas” refers to a fluid that is substantiallyin its vapor phase at ambient conditions (1 atm and 15° C.).

As used herein, the term “fluid” refers to gases, liquids, andcombinations of gases and liquids, as well as to combinations of gasesand solids, and combinations of liquids and solids.

As used herein, the term “condensable hydrocarbons” means thosehydrocarbons that condense at about 15° C. and one atmosphere absolutepressure. Condensable hydrocarbons may include, for example, a mixtureof hydrocarbons having carbon numbers greater than 4.

As used herein, the term “hydrocarbon” refers to an organic compoundthat includes primarily, if not exclusively, the elements hydrogen andcarbon. Hydrocarbons generally fall into two classes: aliphatic, orstraight chain hydrocarbons, and cyclic, or closed ring hydrocarbons,including cyclic terpenes. Examples of hydrocarbon-containing materialsinclude any form of natural gas, oil, coal, and bitumen that can be usedas a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions, or at 15° C. and 1 atm pressure. Hydrocarbon fluids mayinclude, for example, oil, natural gas, coal bed methane, shale oil,pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and otherhydrocarbons that are in a gaseous or liquid state.

As used herein, the term “natural gas” refers to a multi-component gasobtained from a crude oil well (associated gas) or from a subterraneangas-bearing formation (non-associated gas). The composition and pressureof natural gas can vary significantly. A typical natural gas streamcontains methane (C₁) as a significant component. The natural gas streammay also contain ethane (C₂), higher molecular weight hydrocarbons, andone or more acid gases.

As used herein, an “acid gas” means any gas that dissolves in waterproducing an acidic solution. Non-limiting examples of acid gasesinclude hydrogen sulfide (H₂S), carbon dioxide (CO₂), carbon disulfide(CS₂), carbonyl sulfide (COS), mercaptans, or mixtures thereof.

As used herein, the term “tight gas zone” refers to subsurface stratawherein gas is held within rock having very low permeability, such asless than about 0.1 md. Such a formation is may be highly compacted andmay have undergone cementation and recrystalization. Such strata may be,for example, a sandstone, in which case the formation may be referred toas a “tight sand.” In a tight gas formation, it is important to exposeas much of the reservoir as possible, making horizontal and directionaldrilling desirable. This enables the wellbore to run along theformation, opening up more opportunities for the natural gas to enterthe wellbore.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

Description of Selected Specific Embodiments

Methods for managing the production of fluids from a low-permeabilitysubsurface formation are provided herein. The subsurface formation is ina field, such as a coalbed methane field or other field wherein naturalgas is to be produced. The methods have utility during initial fielddevelopment. More specifically, the methods may be used during aninitial production phase when dewatering of the subsurface formationtakes place.

FIGS. 2A and 2B present a unified flowchart showing steps for a method200 of managing the production of fluids from a low-permeabilitysubsurface formation, in one embodiment. As seen in FIG. 2A, the method200 first comprises completing one or more water production wells in asubterranean storage zone. This is shown at Box 210. The “completing”step may be performed by drilling one or more wellbores into thesubterranean zone, and then completing the wellbores as water injectionwells. Alternatively, the “completing” step may mean re-connectingpreviously-plugged wells with the subterranean storage zone.

The subterranean storage zone may be an existing aquifer. Alternatively,the subterranean zone may be a salt cavern or a substantially depletedhydrocarbon reservoir that is available to the operator of the field.Alternatively still, the subterranean storage zone may be a coalbed zonewhich has been previously dewatered. Alternatively still, thesubterranean storage zone may be a section of a coalbed methane field orother field wherein natural gas is to be produced. These are all merelyexamples, as other available reservoirs may be utilized.

The method 200 also includes completing one or more production wells ina first zone. This is provided at Box 215. The first zone is in agas-producing formation in the field. The gas-producing formation may bea shale gas formation. Alternatively, the gas-producing formation may bea so-called tight gas formation. Preferably, however, the formation is acoal-bearing formation. In this instance, the gas produced from theformation is coal bed methane.

The subterranean storage zone may be a lateral extension of the firstzone which has been previously dewatered.

The method 200 also includes the step of co-producing water and methanegas through the production wells. This is shown at Box 220. Productiontakes place from the first zone. During the initial stage of production,production fluids will predominantly include water. As production fromthe first zone continues, the water content of the produced fluids willdecline, and the gas content will increase. The gas itself will compriseat least 50 mole percent methane.

The water produced from the production wells will need to be managed.Accordingly, the method 200 next includes disposing of the waterproduced from the production wells. This is provided at Box 225.Disposal may mean injecting the water into the subterranean storage zoneor releasing the water, preferably after treating, into a surface bodyof water, such as a river, lake, or ocean.

The gas produced from the production wells will also need to be managed.Accordingly, the method 200 further includes the step of flaring the gasinitially produced from the first zone. This is seen at Box 230. Flaringmay be utilized during the initial development of the field as the gasvolumes are very low. As an alternative, however, the gas may be storedor essentially permanently disposed. Storage or disposal may be, forexample, in a separate permeable formation within the subsurface.Storage may alternatively be in a depleted hydrocarbon reservoir.Storage may be desirable as the gas content of the formation fluidsbecomes higher.

The method also includes completing one or more wells in a second zone.This is shown at Box 235 of FIG. 2A. The second zone is a second zone inthe gas-producing formation of the field. The wells include productionwells for producing formation fluids, that is, water and gaseoushydrocarbons. The method 200 then further includes co-producing waterand methane gas from the second zone. This is seen at Box 240.

The water produced from the production wells completed in the secondzone will need to be managed. Accordingly, the method 200 next includesdisposing of the produced water, such as by injecting the water producedfrom the production wells of the second zone into a subterranean zone orby releasing it to a surface body of water, such as a river, lake orocean. This is provided at Box 245. It is understood that someenvironmental treatment or purification of the water may be requiredbefore injection or other disposal. If the water can be treated tosufficient quality, in certain embodiments the produced water may beused for irrigation or drinking.

The gas produced from the production wells completed in the second zonewill also need to be managed. In accordance with the present method 200,the gas produced from the second zone will be temporarily stored in thefirst zone. This is shown at Box 250. Injecting produced gas into thefirst zone has the benefit of causing the first zone to have anincreased gas content. Where the gas-bearing formation is a coal bed,the coal will adsorb much of the gas.

In order to inject produced gas into the first zone, gas injection wellswill need to be provided. Preferably, production wells for the firstzone are converted into gas injection wells. Because the gas istemporarily stored, it is not immediately processed through a gasprocessing facility. However, the method 200 may include constructing agas processing facility. This is shown at Box 255.

To enhance the economics of the field, and in accordance with certainaspects of the present inventions, the gas processing facility is notcompleted before the export of methane gas commences; instead,completion of the gas processing facility is delayed. In one embodiment,substantially final construction of the gas processing facility does nottake place until the gas production rate from the field is able toexceed a designated level. For example, the designated level might be 25percent or, more preferably, 50 percent, or even 75 percent of theanticipated maximum weekly production rate from the field.

In another embodiment, construction of the gas processing facility maynot be finalized until at least two zones of the gas-producing formationhave been dewatered to a designated level. The designated level may be,for example, a reduction in average weekly water production rate of 25percent, or 50 percent, or even 75 percent, from the initial waterproduction rate from the second zone.

The above approaches involve calculating production rate averages.Average production rates, such as daily, weekly, or monthly averages maybe used. In making such calculations, shut-in times for field orfacility maintenance or upsets may be excluded from the averages. Inaddition, for purposes of the construction step of Box 255, the gasprocessing facility may include an export facility.

The method 200 also includes completing one or more production wells ina third zone within the gas-producing formation of the field. This isshown in Box 260 of FIG. 2B. At the same time, the one or moreproduction wells completed in the second zone may be temporarily shutin. This step is seen at Box 265. The shutting-in step is optional asthe operator may choose to at least partially overlap production fromthe second zone and the third zone.

It is noted that the operator could shut in the first zone and commenceinjecting gas from the third zone into the second zone. This is notpreferred as (a) the formation in the first zone is most likely capableof receiving significant quantities of gas without exceeding formationfracture pressures, and (b) such would require the duplicative expenseof converting the production wells in the second zone into injectionwells. However, this is a matter of designer's choice.

In any instance, the method 200 next includes completing one or moreproduction wells in a subsequent zone. This is provided at Box 270. Thesubsequent zone may be a fourth zone, a fifth zone, or more. Thereafter,the operator produces formation fluids from the subsequent zone and allprevious zones. This means that water and hydrocarbon gas is producedfrom through the production wells of the first, second, third, andsubsequent zones. This is seen at Box 275. In the case of at least thefirst and second zones, the zones will contain primarily in situ gas.

Once the gas processing facility is completed, gas processing may begin.Therefore, the method 200 also includes processing gas produced from thesubsequent zone and all previous zones in the gas processing facility.This is shown at Box 280. It is noted here that the gas produced withthe formation fluids may contain not only methane, but also ethane orheavier hydrocarbons. Further, it is possible that the gas will containat least some percentage of acid gases such as carbon dioxide orhydrogen sulfide. Thus, in order to bring the hydrocarbon gas into apipeline specification, the gas processing facility may need to removeat least a portion of acid gas components, remove heavy hydrocarboncomponents, remove inert components, and/or remove water throughdehydration.

It may be that the gas processing facility is completed while gas isbeing produced in the third zone. Therefore, Box 255 may optionallyinclude processing gas produced from the third zone before productionoccurs in the subsequent zone. However, it is preferred that asignificant volume of produced gas be available from previous zonesbefore gas processing commences. Therefore, the operator may produceformation fluids from a fourth, fifth , or even sixth zone beforeprocessing begins in the gas processing facility. Construction of thegas processing facility is in all embodiments delayed in accordance withBox 255.

The water produced from the production wells related to the third andsubsequent zones will also need to be managed. Accordingly, the method200 further includes disposing of the water produced from the productionwells of the third, and subsequent zones. This is seen at Box 285.Disposal may comprise injecting the water into the subterranean storagezone through the connected wells of Box 210. The subterranean zone is aseparate, preferably deeper, zone from the production zones.Alternatively, disposal may involve releasing the produced water into asurface body of water, such as a river, a lake, or an ocean. This may beafter suitable treatment.

It is noted here that the steps presented in Boxes 210 through 280 maybe completed in an order different from the order shown in FIG. 2.Further, some steps may be completed simultaneously or in an overlappingmanner. Certain aspects of the steps in FIGS. 2A and 2B are demonstratedin FIGS. 3A through 3D.

FIGS. 3A through 3D provide illustrative cross-sectional views of afield 300 undergoing hydrocarbon gas development, in one embodiment. Ineach view, the field 300 contains a surface 302, and a subsurface 304.Further, the field 300 contains a gas-producing formation 350.

The gas-producing formation 350 may be a shale gas formation.Alternatively, the gas-producing formation may be a so-called tight gasformation. Preferably, however, the formation 350 is a coal-bearingformation. In this instance, the gas produced from the formation 350 iscoal bed methane.

In FIG. 3A, the gas-producing formation 350 has been sectioned toprovide a first zone 310. A section may reflect a pattern such as a5-spot pattern, or several adjacent patterns of wells. Production wells312 have been completed in the gas-producing formation 350. Formationfluids are being produced from the first zone 310 of the gas-producingformation 350.

In each of FIGS. 3A through 3D, the field 300 also contains a waterstorage reservoir 360. The water storage reservoir 360 may be anexisting aquifer. Alternatively, the water storage reservoir 360 may bea salt cavern or a substantially depleted hydrocarbon reservoir that isavailable to the operator of the field 300. Alternatively still, thewater storage reservoir 360 may be a coalbed zone which has beenpreviously dewatered. For example, the water storage reservoir 360 maybe an extension of the gas-producing formation 350. In each of theseinstances, the water storage reservoir 360 serves as a subterraneanstorage zone. Although the water storage reservoir 360 is shown as beingshallower than the gas-producing formation 350, it may be deeper.

Injection wells 362 are completed in the water storage reservoir 360.The injection wells 362 may have been drilled into the water storagereservoir 360 especially for injection of water. Alternatively, theinjection wells 362 may be converted production wells, such asdewatering or gas production wells that had been previously-plugged. Ineither instance, one or more stages of fluid pumping may be utilized toobtain injection pressures resulting in sufficient and desired injectionrates.

In FIG. 3A, the formation fluids are being transported by the productionwells 312 through the subsurface 304 and to the surface 302. At thesurface 302, the formation fluids are transported through productionlines 314 to a separator 305. The separator 305 separates the formationfluids into liquids and gases. The separator 305 may be a gravityseparator, a centrifugal separator, a flash vessel, or other separationunit for separating liquids from gases.

The liquids comprise primarily water, while the gases comprise primarilymethane. Because methane boils at such a low temperature, it ispreferred that the separator 305 be a low-temperature flash vessel tominimize water vapor. The formation fluids may be taken through acooling unit (not shown) before entry into the separator 305. Theseparator 305 may operate, for example, near ambient temperature and 50psig.

After separation, the produced water exits the separator 305 and istransported for disposal. A water transport line 365 is provided in thefield 300. The water transport line 365 transports water from theseparator 305 to the injection wells 362. From there, water is injectedthrough the injection wells 362 and into the water storage reservoir360.

A gas transport line 315 is also provided. The gas transport line 315transports methane and other gases from the separator 305 to a flare312. From there, the gases are combusted and vented to the atmosphere.However, the operator may choose to temporarily or permanently store thegases in a separate underground reservoir. Alternatively, anabove-ground storage tank or even a transport truck may be used fortemporary storage. It is noted here that at the beginning of productionfrom the first zone 310, the produced fluids comprise predominantlywater. Therefore, relatively little gas is flared or is otherwisecaptured.

FIG. 3B presents a second view of the field 300. This represents a nextstage in development of the field 300. In FIG. 3B, the gas-producingformation 350 has been sectioned into a second zone 320. Productionwells 322 have been completed in the second zone 320. Formation fluidsare now being produced from the second zone 320 and to the surface 302.

The formation fluids are transported through production lines 324 at thesurface 302. From there, the production fluids from the second zone 320are taken to the separator 305. The production fluids from the secondzone 320 are then separated into water and gas. The water exits theseparator 305, and is transported through the water transport line 365to the injection wells 362. The water from the second zone 320 is theninjected into the water storage reservoir 360.

Concerning formation fluids in the gas phase, the gases produced fromthe second zone 320 are not flared or disposed; instead, the gas istransported through the gas transport line 315, and then diverted backthrough production lines 314 and into the production wells 312. Thewells 312 have been temporarily converted to injection wells tofacilitate the injection of gases from the second zone 320 of thegas-producing formation 350 into the first zone 310. In someembodiments, dedicated injector wells into the first zone 310 may beused alternatively or in addition to the wells 312.

Injection of gas from the second zone 320 of the gas-producing formation350 into the first zone 310 provides temporary storage. The gas will bere-produced to the surface 302 in a later stage of field development.However, temporary storage in the first zone 310 allows the developer ofthe field 300 to delay the construction of an expensive, full-capacitygas processing facility.

It is also noted that the injection of gases from the second zone 320 ofthe gas-producing formation 350 into the first zone 310 need not waituntil the first zone 310 has been fully dewatered. In one aspect, theoperator may convert the production wells 312 into injection wells whenwater production from the first zone 310 has dropped from, for example,an initial production rate to a lower designated water production rate.For example, the designated reduction might be a decrease in averageweekly production rate of about 50 percent, or 80 percent, or 90percent.

FIG. 3C presents a third view of the field 300. This represents yet anext stage in the development of the field 300. In FIG. 3C, thegas-producing formation 350 has been sectioned into a third zone 330.Production wells 332 have been completed in the third zone 330.Formation fluids are now being produced from the third zone 330 and tothe surface 302.

The formation fluids are directed into production lines 334. Theformation fluids are delivered through the production lines 334 to theseparator 305. There, the formation fluids from the third zone 330 areseparated into water and gases. The water from the third zone 330 exitsthe separator 305 and is transported through the water transport line365 to the injection wells 362. The water is then injected into thewater storage reservoir 360.

Concerning formation fluids in the gas phase, the gases produced fromthe third zone 330 are not flared or disposed. Instead, the gas isreleased from the separator 305 through the gas transport line 315,directed into one or more of the production lines 314, and injected intothe now-injection wells 312. The wells 312, again, have been temporarilyconverted to injection wells to facilitate the injection of gases fromthe third zone 330 of the gas-producing formation 350 into the firstzone 310. At the same time, the production wells 322 from the secondzone 320 may have been temporarily shut-in, or may continue to produce.

Injection of gas from the third zone 330 of the gas-producing formation350 provides temporary storage. The gas from the third zone 330 willlater be re-produced to the surface 302 along with gas from the first310 and second 320 zones in a later stage of field development.Temporary storage of gas in the first zone 310 again allows thedeveloper of the field 300 to delay the construction of an expensive,full-capacity gas processing facility.

It is also noted that the injection of gas from the third zone 330 ofthe gas-producing formation 350 into the first zone 310 need not waituntil the second zone 320 has been completely dewatered. Some overlap inproduction between the second zone 320 and the third zone 330 may takeplace. In addition, the operator may choose to inject and temporarilystore the gas from the third zone 330 of the gas-producing formation 350into the second zone 320, or another previously dewatered zone, ratherthan the first zone 310. In this instance, the production wells 312 fromthe first zone 310 are shut-in. These are matters of design choice.

FIG. 3D presents a fourth view of the field 300. This represents yet anext stage in the development of the field 300. In FIG. 3D, thegas-producing formation 350 has been sectioned into yet a fourth zone340. Production wells 342 have been completed in the fourth zone 340.Formation fluids are now being produced from the fourth zone 340 and tothe surface 302.

The formation fluids enter production lines 344 at the surface 302. Theformation fluids are transported to the separator 305 for fluidseparation. The separator 305 again separates production fluids from thefourth zone 340 into water and gas. Water from the fourth zone 340 istransported through the water transport line 365 and to the injectionwells 362. The water is then injected into the water storage reservoir360. At the same time, gas is released from the separator 305 into gastransport line 315. Gas transport line 315 is preferably an overheadflash line.

The gases produced from the fourth zone 340 are not flared or disposed;instead, the gases are moved to a new gas processing facility 370. Tothis end, a gas processing facility 370 has now been completed and isready for gas processing and exporting.

In accordance with the present inventions, the gas processing facility370 is not completed before the export of methane gas from the field 300commences; instead, completion of the gas processing facility 370 isdelayed. In one embodiment, substantially final construction of the gasprocessing facility does not take place until the gas production ratefrom the field 300 is able to exceed a designated level. For example,the designated level might be 50 percent or, more preferably, 75percent, or even 100 percent of the anticipated maximum weeklyproduction rate from the field 300. The designated level may be, forexample, 100 mscf/week, or 250 mscf/week.

In another embodiment, construction of the gas processing facility 370may not be finalized until at least two zones of the gas-producingformation have been dewatered to a designated level. The designatedlevel may be, for example, a reduction in average weekly waterproduction rate of 50 percent, or 80 percent for the second zone.Alternatively, construction of the gas processing facility 370 may notbe finalized until at least three zones of the gas-producing formationhave been substantially dewatered and gas produced from the second 320and third 330 zones has been injected into the first zone 310.

Because the gas processing facility 370 is now completed, it is ready toreceive gas production from the gas-producing field 300. In FIG. 3D,gases from the fourth zone 340 are being transported through a gas line372 to the new gas processing facility 370. At the same time, the wells312, 322, 332 completed in the first 310, second 320, and third 330zones, respectively, have been placed back on line.

Formation fluids produced from the first 310, second 320, third 330, andfourth 340 zones are produced to the surface 302. The formation fluidsare transported through production lines 314, 324, and 334,respectively, to the separator 305. The separator 305 separates all ofthese formation fluids into water and gas. Water exits the separator305, and is directed through water transport line 365. The watertransport line 365 carries water to the water injection wells 362, wherewater continues to be injected into the water storage reservoir 360.

Methane and other gases are released from the separator 305 through thegas transport line 315. The gases then travel through gas line 372 andinto the gas processing facility 370. Because gas is produced from threeor four (or even more) zones simultaneously, the gas processing facility370 is able to operate immediately at high or even substantially fullcapacity.

Another method for managing the production of fluids from alow-permeability formation is disclosed herein. FIGS. 4A and 4B presenta unified flowchart showing steps for a method 400 for managing theproduction of formation fluids, in an alternate embodiment.

The method 400 first comprises completing one or more production wellsin a low-permeability, gas-producing formation. This is shown at Box 410of FIG. 4A. The wells are completed in a first zone and in a second zonein a gas producing formation of a field. The gas-producing formation inthe field may be a shale gas formation. Alternatively, the gas-producingformation may be a so-called tight gas formation. Preferably, however,the formation is a coal-bearing formation. In this instance, gasproduced from the formation is coal bed methane. In any instance, theproduced gas comprises greater than 50 mol. percent methane.

The method 400 also includes the step of co-producing water and methanegas through the production wells. This is shown at Box 415. The waterand methane gas together comprise the majority of production fluidsproduced through the production wells from the first and second zones.During the initial stage of production, production fluids willpredominantly be water. As production from the first and second zonescontinues, the water content of the produced fluids declines, and thegas content increases.

The water produced from the production wells will need to be managed.Accordingly, the method 400 also includes disposing of the waterproduced from the production wells. This is provided at Box 420.Disposal may mean injecting the water through injection wells into asubterranean storage zone. Alternatively, disposal may mean transportingthe water to a tank or other place of temporary storage. Alternativelystill, disposal may mean delivering the water for agricultural purposes,or releasing the water into the local water shed. Some environmentaltreatment or purification of the water may be required before thisoption is taken.

The method 400 further includes completing one or more gas injectionwells in a zone in a second subsurface formation, preferably of higherpermeability than that of the first zone. This is provided at Box 425.The “completing” step may be performed by drilling one or more wellboresinto the zone in the second subsurface formation, and then completingthe wellbores as water injection wells. Alternatively, the “completing”step may mean re-connecting previously-plugged wells with the zone inthe second subsurface formation.

The method 400 also includes temporarily storing the gas produced fromthe first zone and the second zone in the zone in the second subsurfaceformation. This is seen at Box 430. The zone in the second subsurfaceformation may be an existing aquifer. Alternatively, the zone in thesecond subsurface formation may be a salt cavern or a substantiallydepleted hydrocarbon reservoir that is available to the operator of thefield. Alternatively still, the zone in the second subsurface formationmay be a coalbed formation which may or may not have been partiallydewatered. In any instance, methane gas produced from the first andsecond zones is injected into the zone in the second subsurfaceformation through the one or more gas injection wells.

The method also includes completing one or more wells in a third zone.This is shown at Box 435 of FIG. 4A. The third zone is in thegas-producing formation of the field. The wells include production wellsfor producing formation fluids, that is, water and gaseous hydrocarbons.The method 400 then further includes co-producing the water and methanegas from the third zone. This is seen at Box 440.

As part of the producing step of Box 440, formation fluids areco-produced from the one or more wells in each of the first and secondzones along with the one or more wells from the third zone. The producedfluids from the first and second zones will contain water. However,because these wells have been at least partially dewatered, they willalso contain a higher percentage of methane gas than the third zone.Preferably, the first and second zones have been dewatered by at least50 percent or, more preferably, by at least 80 percent, before they areplaced in line for co-production with the third zone. Alternatively, thefirst and second zones have been dewatered sufficiently that the weeklyaverage water production rate has fallen by at least 20 percent, or byat least 50 percent from the peak rate. Thus, a high volume of gas isnow available for distribution to a gas processing facility.

The method 400 also includes constructing a gas processing facility.This is shown at Box 445 of FIG. 4A. To enhance the economics of thefield, and in accordance with the present inventions, the gas processingfacility is not completed before the export of methane gas from thezones commences; instead, completion of the gas processing facility isdelayed. In one embodiment, substantially final construction of the gasprocessing facility does not take place until the gas production ratefrom the field is able to exceed a designated level. For example, thedesignated level might be 50 percent or, more preferably, 80 percent, oreven 100 percent of the anticipated maximum weekly production rate fromthe field.

In another embodiment, construction of the gas processing facility maynot be finalized until at least two zones of the gas-producing formationhave been dewatered to a designated level. The designated level may be,for example, a reduction in average weekly water production rate of 25percent, or 50 percent, or more preferably, 75 percent, from initialwater production rate for the combined first and second zones.

The above methods 200, 400 involve calculating production rate averages.Average production rates, such as daily, weekly, or monthly averages maybe used. In making such calculations, shut-in times for field orfacility maintenance or upsets may be excluded from the averages. Inaddition, for purposes of the construction steps of Box 255 and Box 445,the gas processing facility may include an export facility.

The method 400 also includes optionally co-producing water and methanegas from the zone in the second subsurface formation. This is shown inBox 450 in FIG. 4B. Because of previous injections, these formationfluids will contain at least some methane gas, depending on how long theprevious injection took place.

The water produced from the first, second, and third zones, andoptionally from the zone in the second subsurface formation, will needto be managed. Accordingly, the method 400 next includes disposing ofthe water produced from these zones. This is provided at Box 455.Disposal may again mean injecting the water through injection wells intoa subterranean storage zone. Alternatively, disposal may meantransporting the water to a tank or other place of temporary storage.Alternatively still, disposal may mean delivering the water foragricultural purposes, or releasing the water into the local water shed.

In addition, the gas produced from the first, second, and third zones,and optionally from the zone in the second subsurface formation, willneed to be managed. Accordingly, the method 400 includes processing thegas produced from these zones. This is provided at Box 455. Processingis conducted in the newly completed gas processing facility.

FIGS. 5A through 5C provide illustrative cross-sectional views of afield 500 under hydrocarbon gas development in accordance with themethods herein, in an alternate embodiment. These figures depict threeof the stages for implementing the method 400, described above.

In each view, the field 500 contains a surface 502, and a subsurface504. Further, the field 500 contains a low-permeability gas-producingformation 550. The gas-producing formation 550 may be a shale gasformation. Alternatively, the gas-producing formation 550 may be aso-called tight gas formation. Preferably, however, the formation 550 isa coal-bearing formation. In this instance, the gas produced from theformation 550 is coal bed methane.

The field 500 also contains a zone in a second subsurface formation 540.The zone in the second subsurface formation 540 serves as a place oftemporary storage for produced gas from the gas-producing formation 550.The zone in the second subsurface formation 540 may or may not have aclassic geological trap structure. Although injecting into a trapstructure is preferred, such structures may not be available. If thegeostructure of the zone in the second subsurface formation 540 isrelatively flat, the injected gas may slowly migrate laterally. Howeversince the gas may be reproduced in a relatively short amount of time,such as one to three years, a significant amount of the gas may berecaptured as described below in connection with FIG. 5C.

In FIG. 5A, the gas-producing formation 550 has been sectioned toprovide a first zone 510 and a second zone 520. Production wells 512 and522 have been completed in the gas-producing formation 550 for the tworespective zones 510, 520. Formation fluids are being produced from thefirst zone 510 and the second zone 520 through the gas-producingformation 550.

In FIGS. 5A through 5C, only one well 512 is shown completed in thefirst zone 510, and only one well 522 is shown completed in the secondzone 520. Further, only two zones 510, 520 are shown. However, it isunderstood that for purposes of the methods associated with FIGS. 5Athrough 5C, each zone 510, 520 may, and preferably does, have more thanone production well completed therein. Further, there may be only onezone or more than two zones completed in the gas-bearing formation 550during early production.

In each of FIGS. 5A through 5C, the field 500 also contains a waterdisposal location 560. The water disposal location 560 may be anexisting aquifer, such as aquifer 360 shown in FIG. 3A. Alternatively,the water disposal location 560 may be a substantially depletedhydrocarbon reservoir that is available to the operator of the field500. Alternatively still, the water disposal location 560 may be acoalbed zone which has been previously dewatered. For example, the waterdisposal location 560 may be an extension of the gas-producing formation550. In any instance, the water disposal location 560 is shownschematically in each of FIGS. 5A, 5B, and 5C.

In FIG. 5A, formation fluids are being produced from the first 510 andsecond 520 zones of the gas-producing formation 550. The formationfluids are being transported by the production wells 512, 522 throughthe subsurface 504 and up to the surface 502. At the surface 502, theformation fluids are transported through production lines to a separator505. In the arrangement of FIG. 5A, separate lines are shown for theproduction wells 512, 522, with production line 514 transporting fluidsproduced through production well 512, and production line 524transporting fluids produced through production well 522. Fluids fromthe two transport lines 514, 524 merge into line 516 before entering theseparator 505.

The separator 505 separates the formation fluids into liquids and gases.The separator 505 may be a gravity separator, a centrifugal separator, aflash vessel, or other separation unit for separating liquids fromgases.

The liquids comprise primarily water, while the gases comprise primarilymethane. Because methane boils at such a low temperature, it ispreferred that the separator 505 be a low-temperature flash vessel. Theformation fluids may be taken through a cooling unit (not shown) beforeentry into the separator 505. The separator 505 may operate, forexample, at 10° C. and 50 psig to minimize water vapor.

After separation, the produced water exits the separator 505 and istransported for disposal. A water transport line 565 is provided in thefield 500. The water transport line 565 transports water from theseparator 505 to the water disposal location 560.

A gas transport line 515 is also provided. In the field developmentstage shown in FIG. 5A, the gas transport line 515 transports methaneand other gases to a return line 546. From there, the gases enter atransport line 544 associated with injection well 542. The injectionwell 542 is completed in the zone in the second subsurface formation540. The methane and other gases are then injected into the secondsubsurface zone 540 for temporary storage.

In FIGS. 5A through 5C, only one well 542 is shown as a gas injectionwell. However, it is likely that two or more injection wells will becompleted for gas injection. One or more stages of gas compression maybe utilized to obtain injection pressures resulting in sufficient anddesired injection rates through the gas injection well 542.

In the subsurface 504 shown in the illustrative field 500, the zone inthe second subsurface formation 540 is below the gas-producing formation550. A deeper zone is preferred for temporary storage so not tointerfere with drilling into the target gas producing zones. The zone inthe second subsurface formation 540 may be any subsurface stratum havingan acceptable porosity and permeability for receiving and holding water.Such a formation may be a sandstone anticline, a deeper coalbed, anaquifer, or other such formation.

It is noted here that at the beginning of production from the first 510and second 520 zones, the produced fluids comprise predominantly water.Therefore, little gas is stored in the zone in the second subsurfaceformation 540. As dewatering takes place in the first 510 and second 520zones, the gas content of the formation fluids will increase.

Injection of production fluids from the first 510 and second 520 zonesof the gas-producing formation 550 into the zone in the secondsubsurface formation 540 provides temporary storage of gas. The gas willbe re-produced to the surface 502 in a later stage of field development.However, temporary storage in the zone in the second subsurfaceformation 540 allows the developer of the field 500 to delay theconstruction of an expensive, full-capacity gas processing facility.

FIG. 5B presents a second view of the field 500. This represents a nextstage in development of the field 500. In FIG. 5B, the gas-producingformation 550 has been sectioned into a third zone 530. Production wells532 have been completed in the third zone 530. Formation fluids are nowbeing produced from the third zone 530 and to the surface 502.

The formation fluids are transported through production lines 534 at thesurface 502. From there, the production fluids from the third zone 530are taken to the separator 505. En route, the production fluids from thethird zone 530 may be merged with production fluids in lines 514 and 524from the first 510 and second 520 zones, which continue to be produced.The merged production fluids travel together through line 516.

The production fluids from the three zones 510, 520, 530 are separatedin the separator 505 into water and gases. The water exits the separator505 and is transported through the water transport line 565. The wateris then carried to the water disposal location 560, which may be awayfrom the field 500.

The gases produced from the various zones 510, 520, 530 are releasedfrom the separator 505 into the gas line 515. Gas line 515 is preferablyan overhead flash line. In the stage of FIG. 5B, the gases are thentransported through gas transport line 572 into a newly completed gasprocessing facility 570. At the same time, the one or more injectionwells 542 are shut in.

In accordance with the present inventions, the gas processing facility570 is not completed before the export of methane gas from the field 500commences; instead, completion of the gas processing facility 570 isdelayed. In one embodiment, substantially final construction of the gasprocessing facility does not take place until the gas production ratefrom the field 500 is able to exceed a designated level. For example,the designated level might be 50 percent or, more preferably, 75percent, or even 100 percent of the anticipated maximum weeklyproduction rate from the field 500. The designated level may be, forexample, 100,000,000 scf/week, or 250,000,000 scf/week.

In another embodiment, construction of the gas processing facility 570may not be finalized until at least two zones of the gas-producingformation 550 have been dewatered to a designated level. The designatedlevel may be, for example, a reduction in average weekly waterproduction rate from the combined first and second zones of 50 percent,or 75 percent. Alternatively, construction of the gas processingfacility 570 may not be finalized until at least three zones of thegas-producing formation 550 have been substantially dewatered.

Because the gas processing facility 570 is now completed, it is ready toreceive gas production from the gas-producing field 500. As noted, gasesfrom the first 510, second 520 and third 530 zones are being transportedthrough a gas transport line 572 to the gas processing facility 570.Processed gas is then exported from the field 500 through export line574. The processed gas may ultimately be exported via pipeline orliquefied natural gas (LNG) ships.

FIG. 5C presents a third view of the field 500. This represents yet anext stage in development of the field 500. In FIG. 5C, the well 542completed in the zone in the second subsurface formation 540 has beenconverted from an injection well to a production well. Formation fluidsare now being produced from the zone in the second subsurface formation540, through the subsurface 504, and to the surface 502. At the sametime, formation fluids continue to be produced from the gas-producingformation 540 through production wells 512, 522, 532.

The formation fluids from the zone in the second subsurface formation540 enter the fluid line 544 at the surface 502. The formation fluidsare then transported to the separator 505 through transport line 548. Enroute, the formation fluids from the zone in the second subsurfaceformation 540 may be merged with formation fluids being transportedthrough lines 514, 524, and 534. The merged fluids then travel to theseparator 505 through production line 516.

At the separator 505, the formation fluids from the various zones 510,520, 530, 540 are separated just as they were in the stage shown in FIG.5B. Separated water from the zones 510, 520, 530, 540 is transportedthrough the water transport line 565 to the water disposal location,shown schematically at 560. At the same time, gases are released fromthe separator 505 into the gas transport line 515. The gases are routedthrough the gas line 572 to the gas processing facility 570. Because gasis being produced from three or even four zones simultaneously, the gasprocessing facility 570 is able to operate immediately at high or evensubstantially full capacity.

The gas processing facility 570 is being shown in FIGS. 5B and 5Cschematically. It is understood that the gas processing facility will beequipped with various valves, compressors, flow lines, and separatorvessels for substantially removing any water vapor and acid gases fromthe gas introduced from line 572. For example, the gas processingfacility 570 may include a cryogenic distillation tower thatsubstantially “freezes” out carbon dioxide and hydrogen sulfide.Alternatively, the gas processing facility 570 may include a contactorthat utilizes a physical solvent or a chemical solvent to remove acidgases through counter-current or co-current contacting, along with aregenerator vessel. Where the gas is particularly sulfurous, the gasprocessing facility may further include a Klaus sulfur recovery unit, atail gas treating unit, and a combustion furnace. The gas processingfacility may further have a refrigeration system for chilling theprocessed methane into liquefied natural gas (LNG). The current methodsare not limited by the mechanics of gas processing.

As can be seen from the illustrative stages provided in FIGS. 3A through3D, and FIGS. 5A through 5C, methods for managing the production offormation fluids from a low-permeability subsurface formation areprovided herein. The subsurface formation is in a field wherein naturalgas is to be produced. The methods have utility during initial fielddevelopment. More specifically, the methods may be used during aninitial production phase when dewatering of the subsurface formationtakes place. The methods allow the developer of a field to use capitalfor the field more efficiently by delaying or spreading out the erectionof main gas processing equipment until the field is ready forsubstantial gas production and sale. Stated another way, completion ofthe gas processing facility more or less coincides with a gas fieldbeing able to provide gas at near the facilities' rated capacities.

The methods herein may also reduce flaring needs. The methods hereinpermit gas handling early in the development of coalbed methane fieldswhile not requiring excessive facility construction and capital outlayto deal with the modest amounts of gas produced during initialdewatering stages.

In some embodiments herein, the subsurface formation is a coalbedmethane field. The field is divided into two or more coalbed zones. Insome aspects, more than one coalbed zone is simultaneously dewatered toa designated level. The co-produced gas from the produced zones is sentto a single, previously dewatered coalbed zone for temporary storage.Injecting gas into a dewatered coalbed zone to repressurize or evenincrease the pressure above an initial pressure may cause adsorption andstorage of significant amounts of gas. This gas may be stored forperhaps about 1 to about 5 years until gas processing and exportfacilities are available. The increased pressure in the dewatered zonemay help keep water from flowing back into this zone. In someembodiments, wells used for dewatering a coalbed zone are also used forinjecting gas for storage in the zone.

In some embodiments, gas produced from a coalbed zone may be temporarilystored in two or more types of subterranean formations. For example, theproduced gas may be injected into and temporarily stored in a saltcavern, an aquifer zone, or a depleted hydrocarbon reservoir, inaddition to storage in an earlier dewatered coalbed zone.

While it will be apparent that the inventions herein described are wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the inventions are susceptible to modification,variation and change without departing from the spirit thereof.

We claim:
 1. A method for managing the production of fluids from alow-permeability subsurface formation in a field, the fluids comprisingwater and gas, and the method comprising: completing one or more wellsin a first zone within the subsurface formation; producing formationfluids from the first zone so as to at least partially dewater the firstzone; completing one or more wells in a second zone within thesubsurface formation; producing formation fluids from the second zone soas to at least partially dewater the second zone; injecting gas from theformation fluids from the second zone into the first zone for temporarystorage; completing one or more wells in a fourth zone within thesubsurface formation; substantially completing a gas processing facilitywhen (i) the gas production rate from the field is able to exceed adesignated level, or (ii) at least the first and second zones of thesubsurface formation have been dewatered to a designated level; aftersubstantially completing the gas processing facility, co-producingformation fluids from the first zone, the second zone, and the fourthzone; substantially separating water in the co-produced formation fluidsfrom the gas in a separator; and delivering the gas to the substantiallycompleted gas processing facility for processing, the gas comprisinggreater than about 50 mole percent methane before processing.
 2. Themethod of claim 1, wherein the subsurface formation comprises a coalbedzone, a shale gas zone, or a tight gas zone.
 3. The method of claim 2,further comprising: completing one or more water injection wells in asubterranean storage zone; separating water from gas in the formationfluids from the first zone during dewatering; and injecting water fromthe formation fluids from the first zone into the subterranean storagezone.
 4. The method of claim 3, further comprising: flaring a majorityof the gas from the formation fluids from the first zone duringdewatering of the first zone.
 5. The method of claim 3, wherein thesubterranean storage zone is an aquifer, a salt cavern, a depletedhydrocarbon reservoir zone, or a coalbed zone that has been previouslysubstantially dewatered.
 6. The method of claim 3, wherein thesubterranean storage zone is a coalbed zone that is a lateral extensionof the subsurface formation that is undergoing dewatering.
 7. The methodof claim 3, wherein: the subsurface formation is a coalbed zone; and thesubterranean storage zone is an extension of the coalbed zone whereinsubstantial dewatering has previously taken place.
 8. The method ofclaim 2, further comprising: separating water from gas in the formationfluids from the first zone during dewatering; and disposing of the waterby releasing it into a surface body of water.
 9. The method of claim 2,wherein the designated level for the gas production rate from the fieldis at least 25 percent of the anticipated maximum weekly production ratefrom the field.
 10. The method of claim 2, wherein the designated levelfor dewatering the first and second zones of the subsurface formation isa reduction in the average weekly production rate of water in the firstand second zones to less than 50 percent relative to the beginning waterproduction for the second zone.
 11. The method of claim 2, wherein thedesignated level for dewatering the first and second zones of thesubsurface formation is calculated by: establishing a time period;calculating a weekly average water production rate for the at least oneproduction well in the second zone over the time period; determining apeak weekly average water production rate for the at least one well fromthe second zone; and reducing the weekly average water production rateby at least 20 percent from the peak weekly average water productionrate.
 12. The method of claim 11, wherein the weekly average waterproduction rate excludes any well shut-in periods.
 13. The method ofclaim 2, wherein the designated level for dewatering means that thefirst and second zones have been substantially dewatered.
 14. The methodof claim 3, further comprising: completing one or more wells in a thirdzone within the subsurface formation; producing formation fluids fromthe third zone so as to at least partially dewater the third zone;shutting in the one or more wells completed in the second zone;injecting gas from the formation fluids from the third zone into thefirst zone for temporary storage before the gas processing facility issubstantially completed.
 15. The method of claim 14, further comprising:separating water from gas in the formation fluids from the second zoneduring dewatering of the second zone; injecting water from the formationfluids from the second zone into the subterranean storage zone;separating water from gas in the formation fluids from the third zoneduring dewatering; and injecting water from the formation fluids fromthe third zone into the subterranean storage zone.
 16. The method ofclaim 15, wherein co-producing formation fluids further comprisesco-producing formation fluids from the third zone with the formationfluids from the first zone, the second zone, and the fourth zone. 17.The method of claim 1, wherein the gas processing facility refrigeratesthe methane into liquefied natural gas, or introduces the methane into apipeline.
 18. A method for managing the production of fluids from alow-permeability subsurface formation in a field, the fluids comprisingwater and gas, and the method comprising: completing one or more wellsin a first zone within the subsurface formation; producing formationfluids from the first zone so as to at least partially dewater the firstzone; completing one or more injection wells in a zone in a secondsubsurface formation having a permeability that is higher than the firstzone; injecting gas produced from the first zone into the zone in thesecond subsurface formation for temporary storage; completing one ormore wells in a third zone within the low-permeability subsurfaceformation; producing formation fluids from the third zone; substantiallycompleting a gas processing facility when (i) the gas production ratefrom the field is able to exceed a designated level, or (ii) at leastone zone of the subsurface formation has been dewatered to a designatedlevel; after substantially completing the gas processing facility,co-producing formation fluids from the first zone and the third zone;substantially separating water in the co-produced formation fluids fromthe gas in a separator; and delivering the gas to the substantiallycompleted gas processing facility for processing, the gas comprisinggreater than about 50 mole percent methane before processing.
 19. Themethod of claim 18, wherein the low-permeability subsurface formation isa coalbed zone, a shale gas zone, or a tight gas zone.
 20. The method ofclaim 19, wherein the zone in the second subsurface formation comprisesan aquifer, a salt cavern, or a depleted hydrocarbon reservoir zone. 21.The method of claim 20, wherein the zone in the second subsurfaceformation is located in subsurface strata that is deeper than thesubsurface formation that is undergoing dewatering.
 22. The method ofclaim 19, further comprising: completing one or more wells in a secondzone within the low-permeability subsurface formation; producingformation fluids from the second zone so as to at least partiallydewater the second zone; and injecting gas from the formation fluidsfrom the second zone into the zone in the second subsurface formationfor temporary storage before substantially completing the gas processingfacility.
 23. The method of claim 19, further comprising: separatingwater from gas in the formation fluids from the first zone duringdewatering; delivering water from the formation fluids from the firstzone to a water disposal location; and after the gas processing facilityis completed, producing gas from the zone in the second subsurfaceformation and delivering the gas to the separator along with theco-produced formation fluids from the first zone and the third zone. 24.The method of claim 23, wherein: the water disposal location is anaquifer, a salt cavern, a depleted hydrocarbon reservoir zone, or acoalbed zone that has been previously substantially dewatered; anddelivering water to the water disposal location comprises injecting thewater.
 25. The method of claim 23, wherein: the water disposal locationis a surface watershed; and delivering water to the water disposallocation comprises releasing water to the watershed.
 26. The method ofclaim 23, wherein: the subsurface formation is a coalbed zone; the waterdisposal location is an extension of the coalbed zone whereinsubstantial dewatering has previously taken place; and delivering waterto the water disposal location comprises injecting the water into thecoalbed zone.
 27. The method of claim 23, further comprising: completingone or more wells in a second zone within the subsurface formation;producing formation fluids from the second zone so as to at leastpartially dewater the second zone; injecting gas from the formationfluids from the second zone into the zone in the second subsurfaceformation for temporary storage. separating water from gas in theformation fluids from the second zone during dewatering of the secondzone; separating water from gas in the formation fluids from the thirdzone; delivering separated water from the formation fluids to the waterdisposal location; and after the gas processing facility is completed,producing gas from the zone in the second subsurface formation anddelivering the gas to the separator along with the co-produced formationfluids from the first zone, the second zone, and the third zone.
 28. Themethod of claim 19, wherein the designated level for the gas productionrate from the field is at least 25 percent of the anticipated maximumweekly production rate from the field.
 29. The method of claim 19,wherein the designated level for dewatering the at least one zone of thelow-permeability subsurface formation is a reduction in the averageweekly production rate of water in the first zone to less than 50percent relative to the beginning water production for the first zone.30. The method of claim 19, wherein the designated level for dewateringthe at least one zone of the low-permeability subsurface formation iscalculated by: establishing a time period; calculating a weekly averagewater production rate for the at least one production well in the atleast one zone over the time period; determining a peak weekly averagewater production rate for the at least one well from the at least onezone; and reducing the weekly average water production rate by at leastabout 20 percent from the peak weekly average water production rate. 31.The method of claim 30, wherein the weekly average water production rateexcludes any well shut-in periods.
 32. The method of claim 19, whereinthe designated level for dewatering means that the first and secondzones have been substantially dewatered.
 33. The method of claim 19,wherein the gas processing facility refrigerates the methane intoliquefied natural gas, or introduces the methane into a pipeline.
 34. Amethod for managing the production of fluids from a coalbed formation ina field, the fluids comprising water and gas, and the method comprising:completing one or more wells in a first production section within thecoalbed formation; producing formation fluids from the first productionsection so as to at least partially dewater the first section;completing one or more injection wells in a subterranean storage zone;separating the formation fluids into a liquid stream comprisedsubstantially of water, and a gas stream comprising at least 50 molepercent methane gas; injecting the gas from the gas stream into a firstsubsurface formation for temporary storage; injecting water from theliquid stream into a second subsurface formation; completing one or morewells in a subsequent production section within the coalbed formation;substantially completing a gas processing facility for the field; afterthe first production section has been at least partially dewatered andafter the gas processing facility is substantially completed,co-producing formation fluids from the first production section, thesubsequent production section, and the first subsurface formation;substantially separating water in the co-produced formation fluids fromthe gas in a separator; and delivering the gas to the substantiallycompleted gas processing facility for processing.
 35. The method ofclaim 34, wherein the first subsurface formation is a zone in thecoalbed formation.
 36. The method of claim 34, wherein the firstsubsurface formation is an aquifer that is deeper than the coalbedformation.